The generation and recording of borehole acoustic waves is a key measurement employed in oilfield borehole logging. Many borehole tools and methods are currently available for taking acoustic measurements. Some tools include a single source of sonic waves and two or more receivers, however, most of the tools now include two or more acoustic sources and many receivers arranged in an array. While the currently available acoustic tools are useful in providing a large range of information regarding the adjacent formation and the borehole parameters, a primary use of acoustic borehole measurements is the estimation of compressional wave and shear wave formation slowness.
Compressional wave formation slowness is typically estimated using travel times acquired via a first motion detection process. In the case of a single source, two receiver tool suggested by the prior art, formation slowness is estimated by subtracting the arrival times between two receivers and dividing by the inter-receiver spacing. This estimate, however, is subject to inaccuracies due to tool tilt, borehole washouts, bed boundary effects, etc. Additional acoustic sources and receivers and more robust methods such as STC (Slowness-Time-Coherency analysis) among others have been used to reduce the inaccuracies introduced by such environmental effects.
Compressional waves are detectable with monopole measurements. However, in slow formations shear waves are not detectable with monopole measurements. Directional or dipole acoustic sources facilitate detection of both compressional waves and shear waves. Nevertheless, monopole and quadrupole contamination of dipole measurements is a chief problem with acoustic logging tools using arrays of receivers. Acoustic receivers often have different sensitivities, and different sensitivities to the same wave results in a greater possibility of non-dipole contamination. Even similarly or identically manufactured receivers tend to report different amplitudes and time receipts (i.e. amplitude and phase mismatch). Therefore, it is usually necessary to calibrate acoustic logging tools by detecting and correcting amplitude and phase mismatch of the various receivers mounted to the logging tools to improve slowness estimation and downhole modal computation.
Typically, local personnel separately calibrate each individual receiver before each logging operation in an attempt to correct amplitude and phase mismatch. While such calibrations may help, each receiver is calibrated before it is mounted to the tool and with the receivers subjected to atmospheric conditions. However, many factors may combine to cause significant sensitivity variations despite the usual calibration efforts. Some of the factors that cause sensitivity variations include the position and alignment of the receivers, the downhole electronics, environmental factors such as pressure and temperature, and others. Normally the receivers will be subjected to conditions much different from the surface calibration conditions, and it is currently difficult or impossible to account for variations resulting from the eventual positioning and alignment of the receivers on the logging tool. When operated, the receivers are housed in oil-filled sondes, but during calibration they are exposed to air. Therefore, even though some receiver suppliers guarantee small (≦5%) sensitivity variations for receivers individually, after the receivers are mounted to an acoustic tool, the sensitivity variations are usually no longer within the prescribed parameters.
Furthermore, many acoustic logging tools employ dozens of receivers or more. As the demand for more and more accurate logging data increases, so does the number of receivers used with logging tools. Accordingly, the calibration of each individual receiver becomes a very time consuming and expensive proposition. Yet, as discussed above, even the expensive and time consuming methods currently available have limited effectiveness. The current calibration methods neglect many important factors, including the eventual positioning of the receivers on the logging tool and the actual operating environment.
The present invention is directed to overcoming, or at least reducing the effects of, one or more of the problems outlined above.